Vibrating conduit sensors, such as Coriolis mass flowmeters and vibrating densitometers, typically operate by detecting motion of a vibrating conduit that contains a flowing material. Properties associated with the material in the conduit, such as mass flow, density and the like, can be determined by processing measurement signals received from motion transducers associated with the conduit. The vibration modes of the vibrating material-filled system generally are affected by the combined mass, stiffness, and damping characteristics of the containing conduit and the material contained therein.
A typical Coriolis mass flowmeter includes one or more conduits (also called flow tubes) that are connected inline in a pipeline or other transport system and convey material, e.g., fluids, slurries, emulsions, and the like, in the system. Each conduit may be viewed as having a set of natural vibration modes, including for example, simple bending, torsional, radial, and coupled modes. In a typical Coriolis mass flow measurement application, a conduit is excited in one or more vibration modes as a material flows through the conduit, and motion of the conduit is measured at points spaced along the conduit. Excitation is typically provided by a driver, e.g., an electromechanical device, such as a voice coil-type actuator, that perturbs the conduit in a periodic fashion. Mass flow rate may be determined by measuring time delay or phase differences between motions at the transducer locations. Two or more such transducers (or pickoff sensors) are typically employed in order to measure a vibrational response of the flow conduits, and are typically located at positions upstream and downstream of the driver. Instrumentation receives signals from the pickoff sensors and processes the signals in order to derive a mass flow rate measurement.
Flowmeters may be used to perform mass flow rate measurements for a wide variety of fluid flows. One area in which Coriolis flowmeters can potentially be used is in the metering of oil and gas wells. The product of such wells can comprise a multiphase flow, including the oil or gas, but also including other components, including water and air, for example, and/or solids. It is, of course, highly desirable that the resulting metering be as accurate as possible, even for such multiphase flows.
Coriolis meters offer high accuracy for single phase flows. However, when a Coriolis flowmeter is used to measure aerated fluids or fluids including entrained gas, the accuracy of the meter can be significantly degraded. This is similarly true for flows having entrained solids and for mixed-phase fluid flows, such as when hydrocarbon fluids contain water.
Entrained gas is commonly present as bubbles in the flow material. The size of the bubbles can vary, depending on the amount of air present, the flow rate of the flow material, and other factors. A related and significant source of error arises from fluid decoupling. Fluid decoupling results from the motion of the gas bubbles with respect to the liquid as a result of the vibration of the tube. The relative motion of the gas bubbles with respect to the liquid is driven by a buoyant force that is similar to the force that causes bubbles to rise to the surface under the influence of gravity. However, in a vibrating tube, it is the acceleration of the vibrating tube that causes the bubbles to move more than the acceleration of gravity. Because the dense fluid has more mass than the light bubbles, the bubbles have greater acceleration than the fluid in the direction of the tube acceleration. Due to the greater acceleration of the bubbles, on each oscillation of the flow conduit, the bubbles move further than the flow conduit. This is the basis of the decoupling problem. As a result, the fluid that has the lower vibrational amplitude undergoes less Coriolis acceleration and imparts less Coriolis force on the flow conduit than it would in the absence of bubbles. This results in the flow rate and density characteristics being under-reported (negative flow and density errors) when entrained gas is present. Compensating for fluid decoupling has been difficult because there are several factors that determine how much the bubbles move with respect to the fluid. Fluid viscosity is an obvious factor. In a very viscous fluid, bubbles (or particles) are effectively frozen in place in the fluid and little flow error results. Another influence on bubble mobility is the bubble size. The drag on a bubble is proportional to the surface area, whereas the buoyant force is proportional to the volume. Therefore, very small bubbles have a high drag to buoyancy ratio and tend to move with the fluid. Small bubbles subsequently cause small errors. Conversely, large bubbles tend not to move with the fluid and result in large errors. The same holds true for particles. Small particles tend to move with the fluid and cause small errors.
The density difference between the fluid and the gas is another factor that may contribute to flowmeter inaccuracy. The buoyant force is proportional to the difference in density between the fluid and the gas. A high pressure gas can have a high enough density to affect the buoyant force and reduce the decoupling effect.
In addition to measurement errors, the effect of multi-phase flow on Coriolis meters is an increased damping on the flow conduit, resulting in the diminishment of flow conduit vibratory amplitude. Typically, meter electronics compensate for this diminished amplitude by increasing the drive energy, or drive gain, in order to restore the amplitude. To correct for errors due to multi-phase flow, measured variables including density, mass flow, and volume flow are used from a period of single phase flow (liquid only)—these values are referred to as hold values. Hold values are used during two phase flow to replace or improve the accuracy of measured variables. Currently, hold values are determined at a user specified point in time before a parameter goes above a threshold.
Overall, multiphase applications particularly involve an extremely variable amount and behavior of entrained gas and thus exhibit variable measurement performance. Methods have been developed that reduce errors, but there are limitations, and certain types of conditions are more or less effectively handled by prior art methods. By understanding how these various methods work (i.e. sampling, interpolation, etc.), and by relying on the same or similar diagnostics (i.e. drive gain, density) used to create it, it is possible to determine how well the method is working and thus how severe, at least qualitatively, decoupling and other multiphase errors should be.
Indicating measurement confidence or a predicted qualitative accuracy level has benefits to both manufacturers and their customers. Outputting a confidence factor helps to set customer expectations for accuracy on each flowmeter, thus leading to more productive comparisons to separators and other references. Secondly, the confidence indicator tells customers which meters they can fully rely upon and which flowmeters should only be used for estimations or trends. For example, in a hypothetical field of 100 oil wells, 50 might have no gas and can be used with normal meter specifications in mind (i.e. 0.1% error), 30 might have mild gas, and 20 might have severe gas. Those 20 “severe” cases can either be used for trend prediction, or could potentially be removed in favor of another technology if accuracy is critical in that location.
Finally, a confidence factor can also be used to make decisions about optimizing production or measurement accuracy. Turning back to the above hypothetical, if measurement accuracy is highly important on a particular well due to lease allocation, the operator might choose to increase choke pressure or take other operational steps to reduce the amount of gas and improve measurement confidence at that location.
There thus remains a need in the art for a vibratory flowmeter that provides a confidence or accuracy predictor. There remains a need in the art for a vibratory flowmeter that provides a confidence or accuracy predictor in dealing with multiphase flow. Embodiments herein provide methods and devices used to calculate and provide a confidence indicator.